The recovery of hydrocarbons from subterranean zones relies on the process of drilling wellbores. The process includes drilling equipment situated at surface and a drill string extending from the surface equipment to the formation or subterranean zone of interest. The drill string can extend thousands of feet or meters below the surface. The terminal end of the drill string includes a drill bit for drilling (or extending) the wellbore. In addition to the conventional drilling equipment mentioned, the system also relies on some sort of drilling fluid system, in most cases a drilling fluid or “mud” which is pumped through the inside of the pipe, which cools and lubricates the drill bit and then exits out of the drill bit and carries the rock cuttings back to surface. The mud also helps control bottom hole pressure and prevent hydrocarbon influx from the formation into the wellbore which can potentially cause a blow out at surface.
Directional drilling is the process of steering a well away from vertical to intersect a target endpoint or follow a prescribed path. At the terminal end of the drill string is the bottom-hole-assembly (or BHA) which comprises of 1) drill bit; 2) steerable downhole mud motor of rotary steerable system; 3) sensors of survey equipment (Logging While Drilling (LWD) and/or Measurement-while-drilling (MWD)) to evaluate downhole conditions as drilling progresses; 4) equipment for telemetry of data to surface; and 5) other control process equipment such as stabilizers or heavy weight drill collars. The BHA is conveyed into the wellbore by a string of metallic tubulars (drill pipe). MWD equipment is used while drilling to provide downhole sensor and status information to surface in a near real-time mode. This information is used by the rig crew to make decisions about controlling and steering the well to optimize the drilling speed and trajectory based on numerous factors, including lease boundaries, existing wells, formation properties, hydrocarbon size and location, etc. This can include making intentional deviations from the planned wellbore path as necessary based on the information gathered from the downhole sensors during the drilling process. The ability to obtain real time MWD data allows for a relatively more economical and more efficient drilling operation.
The currently used MWD tools contain a sensor package to survey the well bore and send data back to surface by various telemetry methods. Such telemetry methods include but are not limited to the use of hardwired drill pipe, acoustic telemetry, fibre optic cable, Mud Pulse (MP) telemetry and Electromagnetic (EM) telemetry.
MP telemetry involves using a fluid pressure pulse generator to create pressure waves in the drill mud circulating in the drill string. Mud is circulated between the surface and downhole using positive displacement pumps. The resulting flow rate of mud is typically constant. The pulse generator creates pressure pulses by changing the flow area and/or path of the drilling fluid as it passes through the MWD tool in a timed, coded sequence, thereby creating pressure differentials in the drilling fluid. The pressure differentials or pulses may be either negative pulses or positive pulses in nature. Valves that use a controlled restriction within the circulating mud stream create a positive pressure pulse. Some valves are hydraulically powered to reduce the required actuation power typically resulting in a main valve indirectly operated by a pilot valve. The pilot valve closes a flow restriction which actuates the main valve to create a pressure drop.
The pressure pulses generated by the pulse generator are used to transmit information acquired by the downhole sensors. Signals from the sensor modules are received and processed in a data encoder in the BHA where the data is digitally encoded. A controller then actuates the pulse generator to generate the mud pulses which contain the encoded data. For example, the directional or inclination data is conveyed or modulated through the physical mud pulse at a particular amplitude and frequency. Typically a high-frequency sinusoid waveform is used as the carrier signal, but a square wave pulse train may also be used.
A number of encoding schemes can be used to encode data into mud pulses. These schemes include amplitude phase shift keying (ASK), frequency shift keying (FSK), phase shift keying (PSK), or a combination of these techniques. FSK is a frequency modulation scheme in which digital information is transmitted through discrete frequency changes of a carrier wave. The simplest FSK is binary FSK (BFSK). BFSK uses a pair of discrete frequencies to transmit binary (0s and 1s) information. ASK conveys data by changing the amplitude of the carrier wave; PSK conveys data by changing, or modulating, the phase of a reference signal (the carrier wave). ASK and PSK are each based on the modulating of a slightly different parameter of the signal frequency. It is known to combine different modulation techniques. For example, combining ASK and PSK is a digital modulation scheme that conveys data by changing, or modulating, both the amplitude and the phase of a reference signal (or the carrier wave).
The choice of modulation scheme uses a finite number of distinct signals to represent digital data, known as symbol sets. PSK uses a finite number of phases, each assigned a unique pattern of binary digits. Usually, each phase encodes an equal number of bits. Each pattern of bits forms the symbol that is represented by the particular phase. A demodulator at surface, designed specifically for the symbol-set used by the modulator, determines the phase of the received signal and maps it back to the symbol it represents, thus recovering the original data. An example of an 8 state PSK modulation scheme is shown in FIG. 1 (PRIOR ART), wherein a phase diagram and a waveform graph show how an eight (8) state symbol set can be modulated by generating a pressure pulse at a particular phase in that time period. The phase diagram shows how each three (3) bit symbol 000-111 is assigned one of the available 45° phases and the waveform graph shows a pressure pulse representing one of the 3 bits at each of the 8 phases in the time period. A telemetry signal can then be transmitted wherein a pressure pulse is generated per time period having a selected phase representing a particular 3 bit symbol.
To increase the data rate, the time period to transmit each pressure pulse can be reduced; however, reducing the time period also reduces the separation between phases, and increases the difficulty in decoding the telemetry signal at surface, especially when there has been significant attenuation of the signal as it traveled through the earth.